The present invention relates to a system and method for the detection of moisture in natural gas. More specifically, the present invention relates to a technique for determining the level of water vapor present within an industrial natural gas pipeline.
Natural gas has long been used as an energy source because of its low cost and widespread availability. After natural gas is mined, it is purified through several sequential processes, and distributed via networks of underground pipelines that typically transport the gas at a pipe pressure of several hundred pounds per square inch (PSI). Natural gas is sold to the customer as an energy product, and the energy content is generally expressed in British Thermal Units (BTU). The rate that gaseous product is pumped to the customer is measured in standard million cubic feet (SMCF), which is based on the gas volume at a standard pressure and temperature (typically 1 atmosphere pressure/14.73 PSI, and 70 degrees F.).
Contaminants in natural gas, such as water, reduce the BTU capacity of the gas, thereby resulting in a less efficient energy product. Contaminants also corrode delivery pipelines over time potentially resulting in serious safety hazards while also necessitating the costly replacement of segments of the pipeline (downtime for the pipelines can cost upwards of several thousand dollars per second). Accordingly, companies engaged in the mining, purification, and distribution of natural gas continuously monitor the quality of the gas at various stages of production and distribution to prevent such occurrences. One contaminant of particular interest is water vapor (H2O). Excessive buildup of water vapor is a primary cause of pipeline corrosion, and it acts to dilute the natural gas thereby reducing its BTU capacity (thereby making the gas a less efficient energy source).
Distributors of natural gas typically have set maximum allowable levels of H2O within natural gas for various stages of natural gas production and distribution. The final product that is delivered to the customer (usually a large consumer supplier such as Southern California Gas, or Pacific Gas and Electric), is termed “mainline gas.” The typical maximum allowable level of H2O in mainline gas is 7 lbs of H2O per measured million standard cubic feet of CH4 (MMscf); 1 lb/MMscf is approximately 21.1 parts per million by volume, ppmv). This level is termed the “tariff”. When H2O levels exceed tariff levels, plant operation can be suspended resulting in substantial loss of revenue and associated customer lawsuits.
Conventional techniques for measuring water vapor in natural gas rely primarily on the use of chemical sensors. These sensors operate by monitoring the capacitance or dielectric constant of a sensor element (made from compounds such as phosphorous pentoxide (P205) and aluminum oxide) subjected to a sample from the mainline gas. The electrical properties of the sensors change in a quantitative measurable manner as a function of the amount of water vapor present in the sample gas and such changes are translated into water concentration measurements. In such chemical sensors, a low pressure sample of pipeline gas is delivered to the sensor element via a regulation (pressure reduction) system. The gas sample measured by the pipeline is at a much lower pressure than the pipeline itself (typically 10–30 PSI, compared to 800 PSI in the pipeline). Such sensors are typically housed in sampling shelters that also house the accompanying regulation system.
As the sensing elements in chemical sensors are necessarily exposed to gas samples, contaminants in the gas stream such as glycols, amines, and oils directly contact the sensors. While chemical sensors can provide reliable measurements for short periods of time after calibration, the exposure to the contaminants (glycols and amines in particular) soil the sensor, thereby causing drifts in the calibration. This condition results in erroneous readings and can lead to eventual failure if the contaminants build up. Various filters (coalescing, adsorbents, and particle filters) have been employed to minimize the effects of glycol and amine contamination, but historically these filtration schemes are only temporary solutions. This is due in part because the filters are easily saturated with contaminants or they leak and require replacement at irregular intervals.
It should therefore be appreciated that there remains a need for a reliable and durable system and method for detection of water levels in natural gas.